Seal system for downhole tool

ABSTRACT

A downhole tool may include a tubular member having an axis, a wall with a bore, and an orifice extending radially from the bore through the wall. A piston may be configured to be co-axially mounted in the bore of the tubular member and be axially reciprocated therein, the piston having a piston bore. An aperture may extend radially from the piston bore to the bore of the tubular member. First and second glands formed in an outer surface adjacent the aperture. The first gland may be axially spaced apart from the second gland. In addition, a seal system can be configured to be mounted to the piston. The seal system can include a primary seal for the first gland, a secondary seal for the second gland, and the secondary seal is harder than the primary seal.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application is a continuation of International ApplicationNo. PCT/CA2013/000068, filed on Jan. 24, 2013, which claims priority toU.S. Provisional Patent Application No. 61/632,372, filed on Jan. 24,2012 and U.S. Provisional Patent Application No. 61/632,374, filed onJan. 24, 2012, the disclosures of which are incorporated herein byreference in their entireties.

FIELD OF THE DISCLOSURE

The present disclosure relates in general to downhole tools used in thedrilling of wells such as oil and gas wells, including but not limitedto downhole valves, and also to means and apparatus for operatingdownhole tools from the surface.

BACKGROUND

The drilling of an oil and gas well is achieved by attaching a drill bitto the end of a string of drill pipe, and then rotating the drill bitinto a subsurface formation. A weighted water slurry called drillingfluid or drilling mud is flowed downward through the drill string andout through the drill bit to lubricate and cool the drill bit and alsoto wash excavated subsurface material (referred as cuttings) back up tothe surface through the annulus between the drill string and thewellbore.

The path of a wellbore can develop undulations and irregularities duringthe drilling process, particular in deep wells. Drill bit cuttings canbecome lodged in these undulations and therefore not get washed up tosurface. Such unremoved cuttings cause problems in that they can causethe drill string to become stuck within the wellbore, necessitatingspecial measures to dislodge the stuck drill string, at considerableexpense in terms of equipment and labor costs and lost production.

The surface-controllable parameters that an operator uses to drill awell (e.g., mud flow rate, drill string rotational speed, and weight onthe drill bit) are determined by the properties and characteristics ofthe subsurface material that is being drilled through, and also onvarious properties of the drill bit. In addition to those factors, thereare other constraints that can limit the magnitude of the drillingparameters being used. For instance, the amount of weight that can beplaced on the drill bit is affected not only by the properties of thedrill bit but also by the weight of the drill string. Rotational speedis limited by the capabilities of the drilling rig and mud flow rate islimited by the capabilities of the mud pumps. In cases where a downholemotor (or “mud motor”) is used, either to increase the rotational speedof the drill bit or to rotate the drill bit without rotating the drillstring, then the mud motor will present another restriction on the mudflow rate.

Deviated wells (i.e., wellbores drilled using directional drillingtechniques to produce horizontal or otherwise non-vertical wellbores)require the use of a mud motor, and it is such wells that tend toexperience the greatest amount of well path undulation and tortuosity.Because of this tortuosity, it would be advantageous to be able toselectively pump greater amounts of mud through the drill string. Forinstance, after a well has been drilled to a certain depth and the drillstring is being “stroked” up and down to facilitate cuttings cleaning,it would be advantageous to be able to pump more fluid without“overpumping” and possibly damaging the mud motor. This would beachieved by allowing a portion of the mud flow to be diverted out of thedrill string into the wellbore annulus, thus assisting with cuttingsremoval while keeping the mud flow reaching the mud motor withinappropriate limits.

There are known downhole devices incorporating mud ports that arepermanently open to the wellbore annulus, as well as downhole devicesincorporating mud valves that are operable by electrical means. However,these devices have drawbacks that detract from their practical utility.

Mud flow into the wellbore annulus through a permanently open mud portwill be inconsistent, because it will vary with the backpressureprovided by the mud motor. As the mud motor is pulled off bottom andbackpressure decreases, proportionally more mud will flow down throughthe motor and less will flow through the mud port into the annulus.Conversely, as the motor starts drilling and pressure is required todeliver torque through the motor to the drill bit, extra mud flow willbe diverted through the mud port, thus reducing the flow of mud to themotor and consequently reducing its power production. This type ofsystem will tend to result in more incidences of motor stalling, plus adecreased ability to re-start drilling operations after a stall withoutlifting the motor off the bottom of the wellbore and resetting thedrilling parameters.

Electrically-operated valve systems avoid the above-noted problems withrespect to downhole tools with permanently-open mud ports. However,electrically-operated valve systems have drawbacks in terms of highcost, complexity, and tendency for failure.

For the foregoing reasons, there is a need for a downhole mud valve thatcan be operated from the surface while avoiding problems associated withelectrically-operated valves. More particularly, there is a need forsuch a downhole mud valve that is mechanically actuated. In addition, itis desirable for such a mechanically-actuated downhole valve to beoperable by changing one or more drilling parameters from surface,thereby using controls that are already available to the driller, andavoiding the need for extra surface equipment for purposes of operatingthe downhole valve.

It is also desirable that such a surface-controllable downhole valve canbe opened and then will remain in the open position irrespective ofvariations in the drilling parameters, until such time as the operatorselectively closes the valve. Accordingly, there is a need for downholelatching means that can be used to selectively set or “latch” thedownhole valve in the open position, with such downhole latching meansbeing operable from the surface. In addition, it is desirable for suchdownhole latching means to be mechanically actuated.

Ideally, such downhole latching means would also be adaptable for use inassociation with other types of downhole tools that can be cycledbetween “open” and “closed” positions, or “on” and “off” positions. Byway of non-limiting example, a drill string stabilizer may need to beextended for one section of a bit run and then retracted for anothersection, without needing to pull the tool to surface to change itsconfiguration. In such a scenario, downhole latching apparatus ascontemplated above could be provided in association with the stabilizerto cycle the stabilizer between its extended and retracted positionswhile still deployed downhole.

SUMMARY

Embodiments of a downhole and sealing system are disclosed. For example,a downhole tool may include a tubular member having an axis, a wall witha bore, and an orifice extending radially from the bore through thewall. A piston may be configured to be co-axially mounted in the bore ofthe tubular member and be axially reciprocated therein, the pistonhaving a piston bore. An aperture may extend radially from the pistonbore to the bore of the tubular member. First and second glands formedin an outer surface adjacent the aperture. The first gland may beaxially spaced apart from the second gland. In addition, a seal systemcan be configured to be mounted to the piston. The seal system caninclude a primary seal for the first gland, a secondary seal for thesecond gland, and the secondary seal is harder than the primary seal.

In another embodiment, a downhole tool may include a tubular memberhaving an axis, a wall with a bore, an orifice extending radially fromthe bore through the wall, and first and second glands formed in boreadjacent the orifice. The first gland can be axially spaced apart fromthe second gland. A piston may be configured to be co-axially mounted inthe bore of the tubular member and be axially reciprocated therein. Thepiston can have a piston bore, and an aperture extending radially fromthe piston bore to the bore of the tubular member. A seal system may beconfigured to be mounted to the tubular member. The seal system mayinclude a primary seal for the first gland, a secondary seal for thesecond gland, and the secondary seal is harder than the primary seal.

BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments in accordance with the present disclosure will now bedescribed with reference to the accompanying figures, in which numericalreferences denote like parts, and in which:

FIG. 1 is an exploded view of one embodiment of a downhole toolassembly.

FIG. 2 is a longitudinal sectional view through an embodiment of adownhole tool assembly generally as shown in FIG. 1.

FIG. 2A is a longitudinal sectional view through a variant embodiment ofthe assembly shown in FIG. 1.

FIG. 3 is an enlarged section through the downhole valve in FIG. 2,shown in the open position.

FIG. 4 is an enlarged section through the downhole valve in FIG. 2,shown in the closed position.

FIG. 5 is an isometric view of one embodiment of a piston for use in adownhole tool.

FIG. 6A is an isometric view of a first embodiment of a mandrel for usein a downhole latching tool.

FIG. 6B is an isometric view of a second embodiment of a latching toolmandrel.

FIG. 7 is an isometric view of one embodiment of a latch sleeve for usein a downhole latching tool.

FIG. 8 illustrates a mandrel as in FIG. 6A disposed within andoperatively engaging an outer sleeve of a latch sleeve as in FIG. 7.

FIGS. 9A-9E are sequential representations of interactions between thesaw-tooth bosses of the latching tool mandrel and the latch pinsprojecting into the bore of the latching tool sleeve.

FIG. 10 is an exploded isometric view of another embodiment of adownhole tool.

FIG. 11 is a sectional side view of an embodiment of the downhole toolof FIG. 10.

FIGS. 12 and 13 are isometric views of embodiments of a sleeve and apiston, respectively, for a downhole tool.

FIGS. 14 and 15 are isometric views of embodiments of primary andsecondary seals, respectively, for a downhole tool.

FIG. 16 is an enlarged sectional side view of an embodiment of a primaryseal seated in a gland in a piston.

FIGS. 17A1-17A3 are enlarged sectional side views of an embodiment ofseals moving through closed, partially open and fully open positions,respectively, and taken along the line A-A of FIG. 12.

FIGS. 17B1-17B3 are enlarged sectional side views of an embodiment ofseals moving through closed, partially open and fully open positions,respectively, and taken along the line B-B of FIG. 12.

FIG. 18 is a sectional side view of an embodiment of a tool with sealsin a fully open position.

FIGS. 19A-19C are sectional side views of an alternate embodiment of atool depicting closed, partially opening and fully open positions,respectively.

DETAILED DESCRIPTION

FIG. 1 is an exploded view of one embodiment of a downhole valve andlatch assembly 100 in accordance with the present teachings. Assembly100 comprises a generally cylindrical valve housing 10 having an upperend 10U, a lower end 10L, and a bore 11. At least one and preferably twoor more mud ports 12 are provided through the wall of housing 10 topermit fluid flow from bore 11 to the exterior of housing 10.Preferably, hardened steel or tungsten carbide outlet nozzles 13 ofknown type are fitted into mud ports 12 to prevent abrasive erosion ofthe housing wall due to high-velocity flow of drilling mud through mudports 12.

In the embodiment shown in FIG. 1, the exterior surface of housing 10 isconfigured to define helical centralizer elements 15. As well, mud ports12 are shown in FIG. 1 as being directionally oriented so that drillingfluid exiting mud ports 12 will be directed into the wellbore annulus ina substantially uphole direction, thus augmenting the flow of mudwashing cuttings to the surface while also preventing or minimizingdamage that might otherwise result from high-velocity flows of abrasivedrilling mud directed substantially radially outward from mud ports 12against a wellbore into which the valve assembly has been inserted.Although centralizer elements 15 and directionally-oriented mud ports 12will be desirable and preferred in many operational situations, neitherof these features is essential to the broadest embodiments of downholevalves in accordance with this disclosure. For simplicity ofillustration, therefore, centralizer elements are not shown in the otherFigures, and mud ports 12 are shown as simple openings through the wallof housing 10.

The valve assembly also includes a generally cylindrical piston 40 whichis slidably disposed within bore 11 of valve housing 10. Piston 40 hasan upper end 40U, a lower end 40L, and a bore 41. In the illustratedembodiment, piston 40 has two medially-located fluid openings 44,flanked by upper and lower seal sections 45U and 45L carrying orincorporating sealing means (shown by way of non-limiting example aslabyrinth seals comprising multiple, closely-spaced annular grooves). InFIGS. 1, 2, and 3, piston 40 is shown in the open position, with fluidopenings 44 aligned with mud ports 12 in valve housing 10 to allowdiversion of fluid from bore 11 to the exterior of housing 10. However,piston 40 is biased toward the closed position (as in FIG. 4) by meansof a helical spring 35 disposed below piston 40.

In certain embodiments, spring 35 will have a spring constant of lessthan 25 pounds per inch, but that is by way of example only, andembodiments incorporating biasing means in the form of a spring are notlimited to the use of springs having spring constants in the above-notedrange. Spring 35 will preferably be preloaded when the valve assembly isin the closed position, such that the piston will not move to the openposition until a predetermined flow level has been reached. The amountof preload will be a matter of design choice to suit specific cases, butin certain embodiments the preload will be 200 pounds or greater.

As well, a cylindrical wash sleeve 30 having a bore 31 is disposedwithin helical spring 35 largely preventing drilling fluid from enteringthe annular space 37 between wash sleeve 30 and housing 10 and occupiedby spring 35. However, because of the possibility of minor fluid leakagepast piston 40 into annular space 37 under high-pressure flowconditions, at least one drainage hole 32 is preferably provided througha lower region of the wall of sleeve 30 so that any excess fluid thatmay accumulate within annular space 37 can drain into sleeve bore 30 andthus will not impede downward movement of piston 40 and compression ofspring 35. The upper end 30U of wash sleeve 30 is connected to lower end40L of piston 40 (by means of a threaded connection, for example), suchthat wash sleeve 30 and piston 40 are axially movable as a unit. As seenin the Figures, piston 40 may be provided with flattened areas (“wrenchflats”) 42 for engagement by a wrench or other tool being used totighten the threaded connection of between piston 40 and wash sleeve 30.

In the embodiment in FIG. 1, lower end 10L of valve housing 10 comprisesa standard “box” connection, which receives a “double-pin” sub 20 havingan upper pin end 20U which serves as a bearing shoulder for the lowerend 35L of helical spring 35. The upper region of bore 21 of pin sub 20is shown machined to define an annular shoulder 25 which serves as stopmeans limiting the downward travel of wash sleeve 30 and piston 40relative to valve housing 10. However, valve assemblies in accordancewith the present disclosure are not restricted to the use of stop meansprovided in this particular fashion. By way of non-limiting example,FIG. 2A illustrates a variant valve housing 10′ the lower end of whichhas a pin end (rather than a box end as in FIGS. 1 and 2) and in whichbore 11 is machined to form an annular shoulder 18 for receiving lowerend 35L of spring 35, and, below shoulder 18, another annular shoulder19 serving as a lower stop means for wash sleeve 30. This variantembodiment has the advantage of avoiding the need to incorporate a pinsub 20 into the valve assembly.

In the illustrated embodiment, the valve assembly as described above iscoupled with a latching assembly comprising a generally cylindricalmandrel 80 having upper and lower ends 80U and 80L and a bore 81, withlower end 80L being coaxially coupled to upper end 40U of piston 40(such as by way of a threaded connection as shown in the Figures). Asshown in FIGS. 1 through 4, flow restriction means in the form of anorifice 50 of known type and selected characteristics is disposed withinbore 41 of piston 40 below lower end 80L of mandrel 80 and above fluidopenings 44 in piston 40. Orifice 50 is preferably a carbide orifice inwhich the internal diameter can be selectively varied as may beappropriate to suit different fluid flow rates. As best seen in FIGS. 3and 4, orifice 50 may be secured within piston bore 41 by suitable means(such as radial pins 52), in conjunction with suitable sealing means(such as O-ring 54).

The internal diameter of orifice 50 is selected such that a prescribedmud flow rate will generate enough of a pressure drop across orifice 50to induce a downward force on piston 40 greater than the resisting forceof helical spring 35 (or other biasing means), such that piston 40 movesdownwards. When the flow rate is reduced enough that the downward forceinduced by the pressure drop across orifice 50 is less than theresistance of spring 35, piston 40 will slide upward to a stop. Sealsections 45U and 45L on either side of fluid openings 44 prevent mudfrom leaking through fluid openings 44 when they are not aligned withmud ports 12 in housing 10.

Mandrel 80 may optionally be provided with wrench flats 82, as well asone or more drainage holes 83 to allow any fluid accumulating in theannular space between mandrel 80 and housing 10 to drain into mandrelbore 81.

In the mandrel embodiment shown in FIG. 6A, an upper region of mandrel80 is formed with four circumferentially-spaced bosses 85 of generallysaw-toothed configuration, projecting radially outward from the mandrel.Each boss 85 can be considered as comprising contiguously adjacenttrapezoidal sections 86 and 87, with respective upper and lower slopededges 86U, 87U, 86L, and 87L.

Upper sloped edges 86U and 87U both slope in the same general direction,but are not necessarily parallel. Similarly, lower sloped edges 86L and87L both slope in the same general direction without necessarily beingparallel, but their general angular orientation is opposite to that ofupper sloped edges 86U and 87U. This is most clearly understood withreference to mandrel 80 in FIG. 6A, in which upper sloped edges 86U and87U both slope downward and to the right, while lower sloped edges 86Land 87L both slope upward and to the right. Alternatively, bosses 85could be formed such that upper sloped edges 86U and 87U both slopedownward and to the left, while lower sloped edges 86L and 87L bothslope upward and to the left. (In the preceding discussion, the termsupward, downward, right, and left are referable to mandrel 80 whenvertically oriented as it would be when valve and latch assembly 100 isbeing used in the drilling of a vertical wellbore—see FIG. 8, forexample.)

An upper notch 88U is formed where upper sloped edge 86U of trapezoidalsection 86 meets the left side of trapezoidal section 87, and a lowernotch 88L is formed where lower sloped edge 86L of trapezoidal section86 meets the left side of trapezoidal section 87.

FIG. 6B illustrates another variant mandrel 80′ having three saw-toothedbosses 85′ generally similar to bosses 85 in FIG. 6A, but with anaxially-oriented latch pin slot 89 extending upward into each boss 85′from a location analogous to lower notch 88L in boss 85.

Beyond the general configuration described above, mandrel bosses 85 (or85′) do not need to conform to any particular geometric constraints. Theappropriate angular orientation of the sloped upper and lower edges andthe various dimensions of the bosses will be matters of design choice tosuit the requirements of a given case. The sloped upper and lower edgesdo not necessarily have to be linear, but could incorporate curvedportions (with or without linear portions).

Mandrel 80 is disposable within the bore 61 of a cylindrical latchsleeve 60 which has upper and lower ends 60U and 60L. As best seen inFIGS. 2, 3, and 4, latch sleeve 60 is disposed within an upper region ofbore 11 of valve housing 10 in such a manner that sleeve 60 is in afixed axial position relative to housing 10 but is free to rotate withinbore 11. In FIG. 1, latch sleeve 60 is shown as having canted or helicalribs 62 projecting from its outer surface. Such ribs will typically bedesirable to provide fluid flow paths to facilitate removal of anydrilling fluid solids that might accumulate in the annular space betweensleeve 60 and bore 11 and otherwise might impede rotation of sleeve 60within bore 11. However, these ribs are not essential to the broadestembodiments of downhole valve and latch assemblies in accordance withthis disclosure.

As seen in FIGS. 2 through 4, upper end 60U of sleeve 60 is preferablypositioned such that it can bear against the lower end of a pipe section70 connecting to upper end 10U of housing 10, preferably with a thrustbearing 73 and a washer 74 disposed between upper end 60U of sleeve 60and the lower end of pipe section 70. (It should be noted here that pipesection 70 does not form part of the broadest embodiments of anymechanisms or assemblies in accordance with the present disclosure.)

FIG. 7 illustrates a variant of latch sleeve 60 having two pairs oflatch pins which project into sleeve bore 61 far enough to be operablyengageable with bosses 85 on mandrel 80. Each pair of latch pinscomprises an upper latch pin 90 and a lower latch pin 95 which areaxially spaced but circumferentially offset from each other. Thisrelationship between upper and lower latch pins 90 and 95 is mostclearly seen in FIG. 8 and FIGS. 9A-9E.

Each of FIGS. 9A through 9E is a horizontal projection of three of thefour bosses 85 of a mandrel 80 as in FIG. 6A, schematically illustratinghow bosses 85 interact with two pairs of upper and lower latch pins 90and 95 carried by latch sleeve 60 as in FIG. 7, at different stages ofoperation of the latching mechanism. To facilitate a clear understandingof how the latching mechanism works, the three bosses shown in FIGS.9A-9E are differentiated by reference numbers 85.1, 85.2, and 85.3; thetwo upper latch pins are differentiated by reference numbers 90.1 and90.2; and the two lower latch pins are differentiated by referencenumbers 95.1 and 95.2.

In FIG. 9A, the mechanism is latched in the closed position, with lowerlatch pin 95.2 being lodged in lower notch 88L.2 of boss 85.2 such thatdownward movement of mandrel 80 is prevented.

From the position shown in FIG. 9A, the application of an upward forceon mandrel 80 (such as by a reduction in fluid flow rate) will forceupper ramp 87U.2 into contact with upper latch pin 90.2, inducing acounterclockwise rotation of latch sleeve 60 (as viewed looking down)within housing 10 such that upper latch pin 90.2 moves to the rightrelative to boss 85.2 until it is clear of boss 85.2 and “drops” intothe gap between bosses 85.2 and 85.3, and thus does not further restrictupward movement of mandrel 80, as may be seen in FIG. 9B. However,suitable stop means (not shown) will typically be provided to limitupward travel of mandrel 80.

From the position shown in FIG. 9B, the application of a downward forceon mandrel 80 (such as by an increase in fluid flow rate) will forcelower ramp 87L.2 into contact with lower latch pin 95.2, inducing afurther counterclockwise rotation of latch sleeve 60 such that lowerlatch pin 95.2 moves to the right until it is clear of boss 85.2 and“rises” into the gap between bosses 85.2 and 85.3, and thus does notfurther restrict downward movement of mandrel 80, as may be seen in FIG.9C.

From the position shown in FIG. 9C, the application of an upward forceon mandrel 80 will force upper ramp 86U.1 into contact with upper latchpin 90.1, and upper ramp 86U.3 into contact with upper latch pin 90.2,inducing a further counterclockwise rotation of latch sleeve 60 untilupper latch pin 90.1 is lodged in upper notch 88U.1 of boss 85.1 andupper latch pin 90.2 is lodged in upper notch 88U.3 of boss 85.3, all asseen in FIG. 9D. The apparatus is now latched in the open position, withupward movement of mandrel 80 being prevented by upper latch pins 90.1and 90.2.

From the position shown in FIG. 9D, the application of a downward forceon mandrel 80 will force lower ramp 86L.1 into contact with lower latchpin 95.1, and lower ramp 86L.3 into contact with lower latch pin 95.2,inducing a further counterclockwise rotation of latch sleeve 60 untillower latch pin 95.1 is lodged in lower notch 88L.1 and lower latch pin95.2 is lodged in lower notch 88L.3, all as seen in FIG. 9E. It can beseen that the position shown in FIG. 9E is essentially identical to theposition shown in FIG. 9A, with the only difference being that latchsleeve 60 has been rotated ninety degrees counterclockwise.

Other embodiments of a downhole tool may include a sealing system thatallows opening under pressure. In the oil and gas industry, sealingsystems that can operate under high pressure are needed. For example,some drilling tools may be required to release fluid either because theflow is too high or the pressure is too high. Seal systems for suchapplications should be able to move between open and closed positionswherein they are unsealed and sealed, respectively. Exposing a sealwhile it is under pressure generally results in damage to the sealbecause of the explosive release of pressure. In particular, it would bedesirable for a drilling tool seal that can release fluid from thewellbore to the annulus during drilling operations.

There are many different types of sealing systems that are used in theindustry. The challenges that exist when sealing downhole are that thepressures are can be quite high (e.g., up to about 15,000 psi pressuredifferential), the environmental media can be quite varied (e.g., acids,bases, oils, harsh chemicals, suspended solids, steam, etc.), and thetemperature can exceed 150 degrees C. The high temperature requirementalone eliminates many plastic products from contention that wouldotherwise provide an adequate solution.

Situations where a cylinder must seal inside of a bore where the piecesdo not move with respect to each other (i.e., static seals) require themost basic seals, such as elastomeric o-rings. O-rings can be effectivebut they rely on a very close fit between a cylinder (ID) and a piston(OD) where the maximum gap between the two parts is on the order of onlyseveral thousandths of an inch. O-rings seal by using a geometry thatallows them to be pushed towards and slightly into a gap under pressure.This design allows the rubber of the o-ring to bridge the gap whilemaintaining the integrity of the seal.

In applications that require a cylinder to reciprocate, o-ring seals aregenerally not appropriate. The requirement of an o-ring to be pushedinto a gap means that there is a high amount of compression on the sealand that movement of the parts results in wear, damage and eventual sealfailure. Also, if the seal is working in an abrasive environment thereis a high probability that some of the media will abrade the seal. Thisproblem can addressed with a back up ring. Back up rings are typicallyformed from PEEK, Teflon or other harder plastics. For example, a backup ring can be pushed against the ID of a cylinder to reduce the size ofthe extrusion gap for an o-ring. This design helps prevent the intrusionof solids and reduces the pinching of the seal. An alternative toback-up rings is a seal with a geometry that is designed to scrapesolids away while also effecting a tight seal.

Some applications can tolerate the use of a quasi-seal instead of onethat positively excludes fluid movement past the seal. A quasi-seal isgenerally just a very tight restriction for flow and will hold back someamount of pressure under dynamic situations but will generally allow thepressure to equalize across the seal in a static situation. In general,quasi-seals are useful only in dynamic situations where the pressure isgenerated by the flow of fluid. This way, even if there is some amountof fluid transfer across the quasi-seal the overall pressure differenceis maintained. Another limitation of quasi-seals is that they may beused only in situations where the seal is used to isolate two volumes ofthe same type of material. They may not be used to separate air andwater, for example. The fluid transfer across the seal would otherwisecontaminate one or both volumes. An example of a quasi-seal would be themetal piston rings that are used on the piston of an internal combustionengine. The seal is good enough to maintain a certain amount of pressuredifferential under dynamic conditions, but a certain amount of materialtransfer through or past the seal can be tolerated.

Since quasi-seals allow some amount of fluid to leak, they are generallybest used in situations where: (1) the consequences of a small amount ofmaterial transfer across the seal is acceptable; (2) the amount ofpressure that is being sealed is low; and/or (3) the media is generallynot abrasive. Low or no abrasion is required since high pressure willpush media through a quasi-seal at high velocity. If the media isabrasive then some amount of flow erosion can be expected. Thislimitation can be addressed through the use of very hard materials forthe piston and cylinder such as carbide, ceramic, or chrome. However,the amount of time that a quasi-seal can be expected to maintain itsintegrity under these conditions is limited.

Another limitation of quasi-seals is that they tend to act like a filterand encourage the deposit of solid materials from the fluid. That is, ifthe fluid being sealed contains particles in it that are of a scalesimilar to the gap in the quasi-seal then there will be a tendency forthose solids to remain at the site of the seal. If there is a limitedamount of force available to push the piston through the cylinder thenthe filtered solids may compromise the use of whatever device the sealis used with.

These types of seals can work well in situations where the piston stayswithin the bore and the seal (or quasi-seal) can maintain the sameshape. However, a further complication is added for applications thatrequire the piston to move out of the cylinder that is retaining theseal while it is sealing high pressure. If a seal is maintaining a highpressure differential and it is pulled out of its cylinder, there is atleast a small amount of time where fluid of a very high velocity can beexpected to flow past the seal. If the pressure driving this fluidvelocity is high (e.g., in the thousands of psi) and the seal is madeout of a pliable material like rubber or some other elastomer, then itcan be expected that some amount damage to the seal may occur.

Thus, it can be problematic to maintain the integrity of this type ofseal over multiple operations when the following conditions arerequired: (1) two separate volumes need to be intermittently sealed fromone another; (2) the pressure exceeds 1000 psi; a positive seal (notquasi-seal) element is required to keep fluid movement between volumesto zero; and (4) the fluid contains abrasive media.

One solution to this combination of conditions is to use an elastomerseal that is not an o-ring. O-rings can be relatively fragile whenexposed to high forces, such as those generated by high fluid flowrates. The ideal elastomer seal fills its gland, does not rely on anextrusion gap for seal integrity, and has enough compression to maintainthe seal and yet enough open room in the gland for seal compression. Inaddition, a quasi-seal, such as a metal piston-ring type seal, also maybe used on the high pressure side of the piston to act as a “bufferseal” for the elastomer seal. As the elastomer seal is exposed, thebuffer seal prevents high velocity fluid from damaging the elastomer.Finally, an element of the cylinder may be extended, such that the metalpiston ring is retained on at least a portion of its circumference byelements that have the same diameter as the cylinder bore. In this waythe piston may be re-seated inside of the cylinder without having toapply extra axial force to compress the metal piston ring.

Referring now to FIGS. 10-19, other embodiments of a downhole tool 101may include a sealing system 103 that allows opening under pressure. Theother components shown in these drawings but not described may besimilar or substantially identical to those described elsewhere herein.Embodiments of the sealing system 103 may include a piston 105 that hasat least two seals 107, 109 (e.g., four shown as 107, 109, 111, 113)that are mounted on the outer diameter (OD) thereof. The inside diameter(ID) of a cylinder 115 comprises a bore 117 can include an ID that isvery close (e.g., within several thousandths of an inch) of the OD ofthe piston 105.

One of the at least two seals is a primary seal 107 (FIGS. 14 and 16)that can be an elastomeric element similar to an o-ring. However,instead of a circular cross-sectional shape, the primary seal 107 mayinclude one or more of the following attributes: (1) it can besubstantially as wide as the gland or groove 121 that it fits within;(2) the outer (sealing) surface 123 can include beveled edges 125 thatsubstantially come to a crest 127; (3) the crest 127 of the outer edgeof the primary seal 107 can have a diameter that is slightly larger thanthe OD of the piston 105; (4) the cross-sectional area of the primaryseal 107 can be slightly less than the cross-sectional area of the gland121; and/or (5) a small void volume 131 may be included at the ID of theprimary seal 107 to allow the primary seal 107 to flex and squeeze intothe sealing bore 117.

Embodiments of the second sealing element or second seal 109 may includea quasi-seal or buffer seal that is not a total seal, but ratherdramatically slows the passage of fluid past it. The second seal 109 canmaintain a pressure differential if the pressure is created by a dynamicsituation. The second seal 109 can comprise a split metal ring. Thesplit 110 (FIG. 15) may include a stepped lap joint to reduce fluid flowthrough the split 110.

In some versions (FIGS. 17A1-17B3), the second seal 109 can be locatedon the high pressure zone (HPZ) of the primary seal 107. As the piston105 is moved axially towards a completely open position (FIGS. 17A3 and17B3) where both seals 107, 109 are withdrawn or exposed from the bore117 of the housing 115 (thus allowing fluid flow through the seal area),the primary seal 107 is somewhat exposed (FIGS. 17A2 and 17 B2) to theabrasive fluid 112. At the instant that it is exposed there will be anamount of fluid that is at high pressure trying to escape the highpressure zone HPZ. However, this amount is kept to a minimum because assoon as a small amount of fluid moves past the newly exposed primaryseal 107 the flow is slowed down by the second seal 109. This designprotects the elastomeric primary seal 107 from damage by the potentiallyhigh velocity fluid flow.

When the seal system 103 is being reseated the concept also can work inreverse, though there are some other design elements that come intoplay. The second seal 109 seats first, thereby dramatically slowing thefluid flow and making the zone ready for the primary seal 107 to seat.The piston ring that comprises the secondary seal 109 does not expand indiameter. If it had expanded and it had to fit within a smallerdiameter, a higher amount of axial force would be required to force thering to compress. In some cases this may be permissible, although it maybe desirable to provide a predictable amount of force to effectmovement. To limit expansion of the piston ring 109, the cylinder bore117 can be provided with some form of extension 116 (FIG. 12), or theopening that the seals enter can be a radial opening or window ratherthan a fully open bore 117.

Embodiments of the sealing system 103 also may be provided with a bevelor chamfer 118 on the leading edge of the bore 117 or aperture 120 thatthe primary seal 107 will rest within. Such a chamfer 118 can assist theprimary seal 107 to avoid becoming stuck and resist moving back into thesealing bore 117. Thus, the sealing system 103 can include a smooth evenchamfer 118 as well as a bore 117 with elements or extensions 116 thateffectively extend for the entire axial range of motion of the seals107, 109 to constrain the diameter of the secondary seal 109. Once theprimary seal 107 is back within the seal bore 117 then a total seal mayagain be established.

In some embodiments, a sealing system 103 for a downhole tool 101 allowsfor opening and closing while there is a pressure differential acrossthe sealing elements 107, 109. A piston 105 can reciprocate within ahousing 115. The piston 105 may include at least two seals 107, 109 inglands or grooves 121, 122 (FIG. 17A1) on the OD of the piston 105. Thefirst seal 107 may include an elastomer to effect a seal due tocompressive force of the sealing element into the seal bore 117. Theprimary seal 107 can have a geometry that allows it to be easily seatedinside the bore 117 of the cylinder 115. The first seal 107 can have achamfer or sloped top surface 123 (FIG. 16) leading to a crest 127. TheID of the primary seal 107 can be slightly less than the OD of the gland121 so that it is slightly stretched on installation. A void 131 can beon the ID of the primary seal 107 that is larger than the volume ofmaterial that has to be compressed for the seal 107 to fit into thesealing bore 117. The primary seal 107 may be formed from a rubbermaterial, such as HNBR.

Versions of the second seal 109 can be a buffer seal formed from a hardand tough material. The buffer seal can be located to the high pressureside or zone HPZ of the primary seal 107. When both of the seals 107,109 on the piston 105 move out of the area where the seal is maintained(FIGS. 17A3 and 17B3), the buffer seal 109 can be radially constrainedto keep it from expanding. The buffer seal 109 may include a piston ringtype of seal that is made out of metal, and is split 110 forinstallation on the piston 105. A chamfer 118 on the internal surface ofthe edge of the seal bore 117 may be employed.

In some embodiments, a downhole tool 101 may include a tubular member115 having an axis 102, a wall with a bore 117, and an orifice 120 (FIG.12) extending radially from the bore 117 through the wall. A piston 105may be configured to be co-axially mounted in the bore 117 of thetubular member 115 and be axially reciprocated therein. The piston 105can have a piston bore 106 (FIG. 13), an aperture 108 (FIGS. 13 and17A3) extending radially from the piston bore 106 to the bore 117 of thetubular member 115, an outer surface and first and second glands 121,122 (FIG. 17A1) formed in the outer surface adjacent the aperture 108.The first gland 121 can be axially spaced apart from the second gland122.

Embodiments may include a seal system 103 configured to be mounted tothe piston 105. The seal system 103 may include a primary seal 107 forthe first gland 121, a secondary seal 109 for the second gland 122, andthe secondary seal 109 can be harder than the primary seal 107. Versionsof the primary seal 107 can have a hardness in a range of about Shore60A to about Shore 90D. Alternatively, the primary seal 107 can have ahardness in a range of about Shore 60D to about Shore 90D. The primaryseal 107 may include an elastomer formed in a continuous ring. Theprimary seal 107 may include hydrogenated nitrile butadiene rubber(HNBR).

Some embodiments of the primary seal 107 can have an inner diameter (ID)that is less than an outer diameter (OD) of the first gland 121 in arange of about 0.020 inches to about 0.060 inches. The primary seal 107can have an inner diameter ID with a recess 131 (FIG. 16) formedtherein. In some versions, annular legs 132 may be formed on each axialside of the recess 131. Versions of the recess 131 can be concave. Someversions have a volume that is configured to be equal to or greater thana volume of the primary seal 107 that is displaced when the primary seal107 is fully engaged with the bore 117 of the tubular member 115. In aversion, the primary seal 107 can have an axial dimension A, a radialdimension B, and an aspect ratio A:B in a range of about 1:1 to about1:2.

Embodiments of the primary seal 107 can have an outer diameter OD, whichcan comprise one or more of: a non-planar surface; an incline in a rangeof about 5 degrees to about 30 degrees; a surface that is symmetrical; acrest 127 that forms a line that circumscribes the primary seal 107;and/or inclines 125 that slope radially inward from the crest 127, andthe crest 127 bisects the outer diameter OD. In a version, the primaryseal 107, in a relaxed state, can include a radial dimension thatexceeds that of the first gland 121 in a range of about 0.004 inches toabout 0.020 inches.

Embodiments of the secondary seal 109 may include a metallic split ring.It can be steel, and can include a stepped lap joint 110 (FIG. 15). Thesecondary seal 109 can be a buffer seal that is configured to quasi-sealbetween the piston 105 and the bore 117 of the tubular member 115 andallow a leakage rate of less than about 5% of a total flow rate throughthe tool. In other versions, the leakage rate can be less than 4%, lessthan 3%, less than 2%, or even less than 1% of a total flow rate throughthe tool.

Embodiments of the piston 105 (FIG. 13) can further comprise first andsecond axial ends, third and fourth seals 111, 113 can be locatedadjacent the first and second axial ends, respectively. The first andsecond glands 121, 122 can be axially spaced apart from the first andsecond axial ends and the third and fourth seals 111, 113.

In some versions, the tubular member 115 can be the housing 140 (FIG.11) itself, or it can be a sleeve as shown. The sleeve 115 can bemounted coaxially inside the housing 140. The housing 140 can have ahousing aperture 142 that axially registers with the orifice 120. Thehousing 140 can have an axial length that is greater than that of thetubular member 115.

In some versions (FIG. 12), the bore 117 of the tubular member 115 caninclude a coating 150 having a hardness greater than that of the tubularmember 115 itself. For example, the hardness of the coating 150 can bein a range of about 45 HRc to about 65 HRc. The coating 150 may includechromium or other hard materials.

An embodiment of the downhole tool 101 may further include a chamfer 118(FIG. 17A1) formed on the tubular member 115 at an interface between thebore 117 and the orifice 120. For example, the chamfer 118 can be formedat an angle in a range of about 10 degrees to about 30 degrees. As shownin FIG. 12, the orifice 120 may include a plurality of orifices 120. Inan example, each adjacent pair of the orifices 120 can be separated byan extension or bar 116 that extends parallel to the axis 102. The bars116 can have an inner diameter ID that is substantially equal to that ofthe bore 117. In an example, the bar 116 can be configured to constrainan outer diameter OD of the secondary seal 109.

Embodiments of the operation of downhole tool 101 may includeconfiguring the piston 105 to move axially but not rotationally withinthe tubular member 115. The seal system 103 can be configured to have aclosed position (FIGS. 17A1 and 17B1) wherein neither the primary seal107 nor the second seal 109 is in the orifice 120 of the tubular member115. Versions may include a partially open position (FIGS. 17A2 and17B2) wherein only the primary seal 107 is located at least partially inthe orifice 120 of the tubular member 115 and the second seal 109 is notin the orifice 120 of the tubular member 115. Other versions may includea completely open position (FIGS. 17A3, 17B3 and 18) wherein both theprimary seal 107 and the second seal 109 are located at least partiallyin the orifice 120 of the tubular member 115.

Embodiments of the first gland 121 (FIG. 17A1) can be axially spacedapart from the second gland 122 by about 0.1 inches to about 0.8 inches.Versions can have a radial clearance provided between an outer diameterOD of the piston 105 and an inner diameter ID of the tubular member 115,and the radial clearance can be in a range of about 0.001 inches toabout 0.010 inches. In an example, the secondary seal 109 and the secondgland 122 can be configured to be closer to the aperture 108 in thepiston 105 than the primary seal 107 and the first gland 121. Theprimary seal 107 and the first gland 121 can be larger than thesecondary seal 109 and the second gland 122, respectively.

In other embodiments (FIGS. 19A-C), the seal system may be mounted tothe bore 117 of the tubular member 115 or housing, rather than to thepiston 105. For example, a downhole tool may include a tubular member115 having an axis, a wall with a bore 117, an orifice 120 extendingradially from the bore through the wall, and first and second glands121, 122 formed in bore 117 adjacent the orifice 120. The first gland121 can be axially spaced apart from the second gland 122. A piston 105may be configured to be co-axially mounted in the bore 117 of thetubular member 115 and be axially reciprocated therein. The piston 105may include a piston bore 106, and an aperture 108 extending radiallyfrom the piston bore 106 to the bore 117 of the tubular member 115. Inaddition, a seal system may be configured to be mounted to the tubularmember 115. The seal system may include a primary seal 107 for the firstgland 121, a secondary seal 109 for the second gland 122, and thesecondary seal 109 can be harder than the primary seal 107.

The embodiments of the seal system disclosed herein are suitable fornumerous applications, and are not limited to the downhole tool systemsdescribed herein.

Still other embodiments may include one or more of the following items:

Item 1. A downhole tool, comprising:

-   -   a tubular member having an axis, a wall with a bore, and an        orifice extending radially from the bore through the wall;    -   a piston configured to be co-axially mounted in the bore of the        tubular member and be axially reciprocated therein, the piston        having a piston bore, an aperture extending radially from the        piston bore to the bore of the tubular member, an outer surface        and first and second glands formed in the outer surface adjacent        the aperture, and the first gland is axially spaced apart from        the second gland; and    -   a seal system configured to be mounted to the piston, the seal        system comprising a primary seal for the first gland, a        secondary seal for the second gland, and the secondary seal is        harder than the primary seal.

Item 2. The downhole tool of any of these items, wherein:

the primary seal has a hardness in a range of about Shore 60A to aboutShore 90D;

the primary seal has a hardness in a range of about Shore 60D to aboutShore 90D;

the primary seal comprises an elastomer formed in a continuous ring; orthe primary seal comprises hydrogenated nitrile butadiene rubber (HNBR).

Item 3. The downhole tool of any of these items, primary seal has aninner diameter that is less than an outer diameter of the first gland ina range of about 0.020 inches to about 0.060 inches.

Item 4. The downhole tool of any of these items, wherein the primaryseal has an inner diameter with a recess formed therein, and annularlegs are formed on each axial side of the recess.

Item 5. The downhole tool of any of these items, wherein the recess hasa volume that is configured to be equal to or greater than a volume ofthe primary seal that is displaced when the primary seal is fullyengaged with the bore of the tubular member.

Item 6. The downhole tool of any of these items, wherein the primaryseal comprises an axial dimension A, a radial dimension B, and an aspectratio A:B in a range of about 1:1 to about 1:2.

Item 7. The downhole tool of any of these items, wherein the primaryseal has an outer diameter, and wherein the outer diameter comprises oneor more of:

a non-planar surface;

an incline in a range of about 5 degrees to about 30 degrees;

a crest that forms a line that circumscribes the primary seal; and

inclines that slope radially inward from a crest, and the crest bisectsthe outer diameter.

Item 8. The downhole tool of any of these items, wherein the primaryseal, in a relaxed state, comprises a radial dimension that exceeds thatof the first gland in a range of about 0.004 inches to about 0.020inches.

Item 9. The downhole tool of any of these items, wherein the secondaryseal comprises a metallic split ring.

Item 10. The downhole tool of any of these items, wherein the secondaryseal comprises steel and has a stepped lap joint.

Item 11. The downhole tool of any of these items, wherein the secondaryseal comprises a buffer seal that is configured to quasi-seal betweenthe piston and the bore of the tubular member and allow a leakage rateof less than about 5% of a total flow rate through the tool.

Item 12. The downhole tool of any of these items, wherein the pistonfurther comprises first and second axial ends, third and fourth sealsare located adjacent the first and second axial ends, respectively, andthe first and second glands are axially spaced apart from the first andsecond axial ends and the third and fourth seals.

Item 13. The downhole tool of any of these items, wherein the tubularmember is a sleeve, the sleeve is mounted coaxially inside a housing,the housing has a housing aperture that axially registers with theorifice, and the housing has an axial length greater than that of thetubular member.

Item 14. The downhole tool of any of these items, wherein the bore ofthe tubular member comprises a coating having a hardness greater thanthat of the tubular member itself, the hardness of the coating is in arange of about 45 HRc to about 65 HRc, and the coating comprises one ormore of chromium, carbide and ceramic.

Item 15. The downhole tool of any of these items, further comprising achamfer formed on the tubular member at an interface between the boreand the orifice.

Item 16. The downhole tool of any of these items, wherein the chamfer isformed at an angle in a range of about 10 degrees to about 30 degrees.

Item 17. The downhole tool of any of these items, wherein the orificecomprises a plurality of orifices, each adjacent pair of the orifices isseparated by a bar that extends parallel to the axis, and the bar has aninner diameter that is substantially equal to that of the bore.

Item 18. The downhole tool of any of these items, wherein the bar isconfigured to constrain an outer diameter of the secondary seal.

Item 19. The downhole tool of any of these items, wherein the piston isconfigured to move axially but not rotationally within the tubularmember.

Item 20. The downhole tool of any of these items, wherein the sealsystem is configured to have a closed position wherein neither theprimary seal nor the second seal is in the orifice of the tubularmember, a partially open position wherein only the primary seal islocated at least partially in the orifice of the tubular member and thesecond seal is not in the orifice of the tubular member, and acompletely open position wherein both the primary seal and the secondseal are located at least partially in the orifice of the tubularmember.

Item 21. The downhole tool of any of these items, wherein the firstgland is axially spaced apart from the second gland by about 0.1 inchesto about 0.8 inches.

Item 22. The downhole tool of any of these items, wherein a radialclearance is provided between an outer diameter of the piston and aninner diameter of the tubular member, and the radial clearance is in arange of about 0.001 inches to about 0.010 inches.

Item 23. The downhole tool of any of these items, wherein the secondaryseal and the second gland are configured to be closer to the aperture inthe piston than the primary seal and the first gland, and the primaryseal and the first gland are larger than the secondary seal and thesecond gland, respectively.

Item 24. A downhole tool, comprising:

-   -   a tubular member having an axis, a wall with a bore, an orifice        extending radially from the bore through the wall, first and        second glands formed in bore adjacent the orifice, and the first        gland is axially spaced apart from the second gland;    -   a piston configured to be co-axially mounted in the bore of the        tubular member and be axially reciprocated therein, the piston        having a piston bore, and an aperture extending radially from        the piston bore to the bore of the tubular member; and    -   a seal system configured to be mounted to the tubular member,        the seal system comprising a primary seal for the first gland, a        secondary seal for the second gland, and the secondary seal is        harder than the primary seal.

Item 25. The downhole tool of item 24, wherein the aperture in thepiston comprises a plurality of apertures, each adjacent pair of theapertures is separated by a bar that extends parallel to the axis, andthe bar has an outer diameter that is substantially equal to that of thepiston, and the bar is configured to constrain an inner diameter of thesecondary seal.

It is to be understood that the scope of the claims appended heretoshould not be limited by the preferred embodiments described andillustrated herein, but should be given the broadest interpretationconsistent with the description as a whole. It is also to be understoodthat the substitution of a variant of a claimed element or feature,without any substantial resultant change in functionality, will notconstitute a departure from the scope of the disclosure.

In this patent document, any form of the word “comprise” is to beunderstood in its non-limiting sense to mean that any element followingsuch word is included, but elements not specifically mentioned are notexcluded. A reference to an element by the indefinite article “a” doesnot exclude the possibility that more than one of the element ispresent, unless the context clearly requires that there be one and onlyone such element.

Any use of any form of the terms “connect”, “engage”, “couple”,“attach”, or any other term describing an interaction between elementsis not meant to limit the interaction to direct interaction between thesubject elements, and may also include indirect interaction between theelements such as through secondary or intermediary structure. Relationalor relative terms (such as but not limited to “horizontal”, “vertical”,“parallel”, “perpendicular”, and “coaxial”) are not intended to denoteor require absolute mathematical or geometrical precision. Accordingly,such terms are to be understood as denoting or requiring substantialprecision only (e.g., “substantially horizontal”) unless the contextclearly requires otherwise.

Wherever used in this document, the terms “typical” and “typically” areto be interpreted in the sense of representative or common usage orpractice, and are not to be understood as implying invariability oressentiality.

We claim:
 1. A downhole tool, comprising: a tubular member having anaxis, a wall with a bore, and an orifice extending radially from thebore through the wall; a piston configured to be co-axially mounted inthe bore of the tubular member and be axially reciprocated therein, thepiston having a piston bore, an aperture extending radially from thepiston bore to the bore of the tubular member, an outer surface andfirst and second glands formed in the outer surface adjacent theaperture, and the first gland is axially spaced apart from the secondgland; and a seal system configured to be mounted to the piston, theseal system comprising a primary seal for the first gland, a secondaryseal for the second gland, and the secondary seal is harder than theprimary seal.
 2. The downhole tool of claim 1, wherein: the primary sealhas a hardness in a range of about Shore 60A to about Shore 90D; theprimary seal has a hardness in a range of about Shore 60D to about Shore90D; the primary seal comprises an elastomer formed in a continuousring; or the primary seal comprises hydrogenated nitrile butadienerubber (HNBR).
 3. The downhole tool of claim 1, primary seal has aninner diameter that is less than an outer diameter of the first gland ina range of about 0.020 inches to about 0.060 inches.
 4. The downholetool of claim 1, wherein the primary seal has an inner diameter with arecess formed therein, and annular legs are formed on each axial side ofthe recess.
 5. The downhole tool of claim 1, wherein the primary sealhas an outer diameter, and wherein the outer diameter comprises one ormore of: a non-planar surface; an incline in a range of about 5 degreesto about 30 degrees; a crest that forms a line that circumscribes theprimary seal; and inclines that slope radially inward from a crest, andthe crest bisects the outer diameter.
 6. The downhole tool of claim 1,wherein the primary seal, in a relaxed state, comprises a radialdimension that exceeds that of the first gland in a range of about 0.004inches to about 0.020 inches.
 7. The downhole tool of claim 1, whereinthe secondary seal comprises a metallic split ring.
 8. The downhole toolof claim 1, wherein the secondary seal comprises a buffer seal that isconfigured to quasi-seal between the piston and the bore of the tubularmember and allow a leakage rate of less than about 5% of a total flowrate through the tool.
 9. The downhole tool of claim 1, wherein thepiston further comprises first and second axial ends, third and fourthseals are located adjacent the first and second axial ends,respectively, and the first and second glands are axially spaced apartfrom the first and second axial ends and the third and fourth seals. 10.The downhole tool of claim 1, wherein the tubular member is a sleeve,the sleeve is mounted coaxially inside a housing, the housing has ahousing aperture that axially registers with the orifice, and thehousing has an axial length greater than that of the tubular member. 11.The downhole tool of claim 1, wherein the bore of the tubular membercomprises a coating having a hardness greater than that of the tubularmember itself, the hardness of the coating is in a range of about 45 HRcto about 65 HRc, and the coating comprises one or more of chromium,carbide and ceramic.
 12. The downhole tool of claim 1, furthercomprising a chamfer formed on the tubular member at an interfacebetween the bore and the orifice.
 13. The downhole tool of claim 12,wherein the chamfer is formed at an angle in a range of about 10 degreesto about 30 degrees.
 14. The downhole tool of claim 1, wherein theorifice comprises a plurality of orifices, each adjacent pair of theorifices is separated by a bar that extends parallel to the axis, andthe bar has an inner diameter that is substantially equal to that of thebore.
 15. The downhole tool of claim 14, wherein the bar is configuredto constrain an outer diameter of the secondary seal.
 16. The downholetool of claim 1, wherein the piston is configured to move axially butnot rotationally within the tubular member.
 17. The downhole tool ofclaim 1, wherein the seal system is configured to have a closed positionwherein neither the primary seal nor the second seal is in the orificeof the tubular member, a partially open position wherein only theprimary seal is located at least partially in the orifice of the tubularmember and the second seal is not in the orifice of the tubular member,and a completely open position wherein both the primary seal and thesecond seal are located at least partially in the orifice of the tubularmember.
 18. The downhole tool of claim 1, wherein a radial clearance isprovided between an outer diameter of the piston and an inner diameterof the tubular member, and the radial clearance is in a range of about0.001 inches to about 0.010 inches.
 19. The downhole tool of claim 1,wherein the secondary seal and the second gland are configured to becloser to the aperture in the piston than the primary seal and the firstgland, and the primary seal and the first gland are larger than thesecondary seal and the second gland, respectively.
 20. A downhole tool,comprising: a tubular member having an axis, a wall with a bore, anorifice extending radially from the bore through the wall, first andsecond glands formed in bore adjacent the orifice, and the first glandis axially spaced apart from the second gland; a piston configured to beco-axially mounted in the bore of the tubular member and be axiallyreciprocated therein, the piston having a piston bore, and an apertureextending radially from the piston bore to the bore of the tubularmember; and a seal system configured to be mounted to the tubularmember, the seal system comprising a primary seal for the first gland, asecondary seal for the second gland, and the secondary seal is harderthan the primary seal.